Process for producing oil

ABSTRACT

Heavy oil or bitumen is recovered by injecting an oil recovery formulation comprising ammonia and steam having a vapor quality of from greater than 0 to less than 0.7, or injecting components thereof, into an underground oil-bearing formation comprising oil or bitumen having a total acid number of at least 0.1 and producing oil or bitumen from the formation after injection of the oil recovery formulation, or components thereof, into the formation.

This application claims priority from U.S. Provisional Application Ser.No. 61/746,214, filed Dec. 27, 2012, which is hereby incorporated byreference in its entirety.

FIELD OF THE INVENTION

The present invention is directed to a process for producing oil. Inparticular, the present invention is directed to a process for producinga heavy oil or bitumen having a measurable total acid number.

BACKGROUND OF THE INVENTION

Large deposits of heavy oil or bitumen are present in some areas of theworld. These deposits offer the opportunity to capture large quantitiesof oil, however, the nature of the heavy oil or bitumen rendersrecovering the oil difficult. Heavy oil and bitumen contain more highmolecular weight hydrocarbons such as asphaltenes and resins than lightcrudes, which renders the heavy oil/bitumen much more viscous than lightcrudes. Viscous heavy oil or bituminous crudes are more difficult tomobilize and produce from a subterranean formation than crudes of lowviscosity since the viscous crudes do not flow easily.

Heat has been used for enhancing oil production from subterranean heavyoil and bitumen-containing formations. Heat applied to the heavy oil orbitumen within the formation reduces the viscosity of heavy oil orbitumen so the oil in place in the formation may flow more freely and bemobilized for production.

Steam flooding is one method that is commonly used to provide heat tosubterranean heavy oil and bitumen-containing formations. Steam isinjected into a heavy oil or bitumen-containing subterranean formationthrough an injection well extending into the formation, and is contactedwith the oil in place in the formation to heat the oil, mobilizing theoil for production from the formation. Steam provides sensible heat andlatent heat of condensation to the oil in the formation to reduce theviscosity of the oil. Furthermore, the water condensed from the steammay form an oil-in-water emulsion with the oil in the formation, wherethe emulsion has a viscosity on the same order of magnitude as water andsubstantially less than the oil itself, where the oil-in-water emulsionmay be mobilized for production from the formation. The reducedviscosity oil and the oil-in-water emulsion are then produced from theformation.

Steam flooding may be effected by injecting the steam into a heavy oilor bituminous subterranean formation through one or more injection wellsfor a period of time to lower the viscosity of the oil near theinjection wellbore, then stopping the injection of steam and pumping thereduced viscosity oil from the formation through the well used to injectthe steam into the formation. When the oil production drops off, steaminjection may be resumed to heat more oil in the formation, followed byfurther production. Steam flooding may also be effected by continuouslyinjecting the steam into a heavy oil or bitumen-containing subterraneanformation through one or more vertical injection wells and continuouslyproducing oil from the formation through one or more vertical productionwells.

Steam-Assisted-Gravity-Drainage (“SAGD”) is a method for producing heavyoil or bitumen from a heavy oil or bitumen-containing subterraneanformation that utilizes gravity in combination with steam inducedviscosity reduction of bitumen or heavy oil to recover oil from theformation. A paired injection well and production well are drilled sothat portions of the wells that are in contact with the oil-containingportion of the formation extend horizontally through the formation,where the horizontally extending portions of the paired injection welland production well are aligned in parallel—the horizontally extendingportion of the production well located from 2-10 meters below thehorizontally extending portion of the injection well. Steam is injectedinto the formation through the injection well, heating the bitumen orheavy oil around the injection well to reduce the viscosity thereof andto form an oil-in-water emulsion having reduced viscosity relative tothe bitumen or heavy oil in the formation. The reduced viscosity bitumenor heavy oil and the oil-in-water emulsion are mobilized and falltowards the production well, which produces the mobilized oil andemulsion.

When conducting a SAGD process, a steam chamber is formed extending fromthe injection well upwards into the formation. As steam is injected intothe formation, the bitumen or heavy oil is mobilized and drains towardsthe production well, leaving freed pore space in the formation which isfilled with further steam being injected into the formation. As steam isinjected into the formation it traverses the steam chamber to contactnew bitumen or heavy oil at the edges of the steam chamber, mobilizingthe new bitumen or heavy oil for production from the production well.

Patent application publication WO 2009/108423 A1 discloses a method ofimproving the recovery of bitumen from a subterranean formation using aSAGD process in which steam and a volatile amine, steam and a volatileamine and ammonia, or high quality steam (having a vapor quality of atleast 0.7) and ammonia are injected into the formation. The volatileamine, volatile amine plus ammonia, or ammonia in combination with thehigh quality steam traverse the steam chamber to contact bitumen at theedge of the steam chamber. The volatile amine and/or ammonia canpotentially react with naphthenic acids in the bitumen to formoil-emulsifying soaps. These soaps may combine with condensed water toform a low viscosity oil-in-water emulsion that may drain to theproduction well for recovery from the formation.

Injection of steam into the formation from the injection well in a SAGDprocess or a combination of high quality steam and ammonia, amines, oramines plus ammonia does not mobilize all of the bitumen or heavy oil inthe steam chamber. Significant quantities of residual oil are left inplace within the steam chamber that are not recovered.

Improvements to steam-based bitumen or heavy oil recovery processes aredesirable. In particular, improvements to steam-based processes forrecovery of bitumen or heavy oil that improve recovery of residual oilare desirable.

SUMMARY OF THE INVENTION

In one aspect, the present invention is directed to a process forproducing oil comprising injecting an oil recovery formulationcomprising ammonia and steam into a subterranean oil-bearing formationcomprising an oil or bitumen having a total acid number (“TAN”) of atleast 0.1, wherein the steam has a vapor quality of from greater than 0to less than 0.7; and producing oil or bitumen from the formation afterinjection of the oil recovery formulation into the formation. In oneaspect, the process further comprises the steps of forming a steamchamber in the oil-bearing formation, injecting the oil recoveryformulation into the steam chamber in the formation, and recoveringresidual oil from the steam chamber after injecting the oil recoveryformulation into the formation.

In another aspect, the present invention is directed to a process forproducing oil, comprising injecting steam having a vapor quality of fromgreater than 0 to less than 0.7 into an oil-bearing formation comprisingan oil or bitumen having a TAN of at least 0.1; injecting ammonia intothe oil bearing formation to contact the steam and form an oil recoveryformulation comprising ammonia and steam having a vapor quality of fromgreater than 0 to less than 0.7; contacting the oil recovery formulationwith oil in the formation; and producing oil from the formation aftercontacting the oil with the oil recovery formulation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an oil production system that may be used to practicethe process of the present invention.

FIG. 2 illustrates an oil production system that may be used to practicethe process of the present invention.

FIG. 3 illustrates a processing facility that may be used in thepractice of the process of the present invention.

FIG. 4 illustrates an oil production system that may be used to practicethe process of the present invention, depicting an oil recoveryformulation being injected into an oil-bearing formation.

FIG. 5 illustrates an oil production system that may be used to practicethe process of the present invention, depicting production of oil fromthe formation.

FIG. 6 illustrates an oil production system that may be used to practicethe process of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

The present invention is directed to a process for enhancing therecovery of oil from a subterranean formation containing heavy oil orbitumen. An oil recovery formulation comprising ammonia and low qualitysteam—in particular, steam having a vapor quality of less than 0.7—maybe injected into the formation and oil may be produced from theformation after injection of the oil recovery formulation into theformation. The combination of ammonia and low quality steam in the oilrecovery formulation produces ammonium hydroxide in the liquid phaseaqueous condensate portion of the low quality steam so that the ammoniumhydroxide is present in the oil recovery formulation as the oil recoveryformulation is injected into the formation. The ammonium hydroxide mayreact with petroleum acids, e.g. naphthenic acids, in the bitumen orheavy oil in the immediate vicinity of the injecting well to form anoil-emulsifying soap that promotes the formation of an oil-in-wateremulsion with condensed water from the steam, where the oil-in-wateremulsion may have a significantly reduced viscosity and interfacialtension relative to the bitumen or heavy oil in the formation. The steammay also provide sensible and latent heat to bitumen or heavy oil in theimmediate vicinity of the injecting well to reduce the viscosity of thebitumen or heavy oil in the immediate vicinity of the injecting well.The reduced viscosity bitumen or heavy oil and the oil-in-water emulsionmay be mobilized in the formation for production from the formation.

Alternatively, the process of the present invention may compriseinjecting low quality steam—in particular, steam having a vapor qualityof less than 0.7—and gaseous ammonia or liquid ammonia separately into aheavy oil or bitumen containing formation in which the heavy oil orbitumen has a TAN of at least 0.1, and mixing the injected steam andammonia in the immediate vicinity of the injecting well. The mixture oflow quality steam and ammonia produces or contains ammonium hydroxide asa result of interaction with liquid phase water with ammonia, where theammonium hydroxide may react with petroleum acids in the bitumen orheavy oil in the immediate vicinity of the injecting well to form anoil-emulsifying soap that promotes the formation of an oil-in-wateremulsion that is less viscous and has lower interfacial tension than theheavy oil or bitumen in the formation and that is mobilized forproduction from the formation. The steam also provides sensible andlatent heat to bitumen or heavy oil in the immediate vicinity of theinjecting well to reduce the viscosity and mobilize the bitumen or heavyoil for production. The mobilized oil and oil-in-water emulsion may beproduced from the formation.

The process of the present invention is suited for improving recovery ofoil in a SAGD process relative to conventional SAGD processes. As notedabove, significant quantities of oil are left as residual oil in thesteam chamber formed in a SAGD process. SAGD typically fails to recoverabout 45% of the initial bitumen or heavy oil in a formation.

In conventional SAGD processes, high quality steam is injected throughthe steam chamber to the edge of the steam chamber where the steamcontacts bitumen, cools and provides sensible and latent heat to thebitumen at the edge of the steam chamber, reducing the viscosity andmobilizing the bitumen for production. The mobilized bitumen falls tothe producing well, expanding the steam chamber as it is removed fromthe formation. A substantial portion of the heat provided by the highquality steam to the bitumen at the edge of the steam chamber is latentheat, which is not provided to residual oil left in the steam chambersince the steam is dry when passing through the steam chamber.Therefore, a substantial amount of the residual oil in the steam chamberis not mobilized for production by injection of high quality steam intothe formation.

WO 2009/108423 A1 discloses a process for improving the recovery ofbitumen in a SAGD process by injecting a mixture of high quality steamand ammonia, an amine and ammonia, or an amine into a subterraneanbitumen formation. The process of WO 2009/108423 does not promotesubstantial recovery of residual oil in the steam chamber when highquality steam and ammonia are used in the process. The high qualitysteam is dry as it passes through the steam chamber, and fails toprovide latent heat of condensation to lower the viscosity of theresidual oil. Further, production of a mobile oil-in-water emulsion ofthe residual oil in the steam chamber is avoided since emulsion-inducingammonium hydroxide is not formed in the steam chamber by reaction ofammonia with liquid phase water. The high quality steam is dry as itpasses through the steam chamber and insufficient liquid phase watercondensate is present in the steam chamber to form ammonium hydroxidewith the injected ammonia sufficient to produce recoverable quantitiesof an oil-in-water emulsion of the residual oil.

The process of the present invention may promote recovery of residualoil from the steam chamber. Unlike the process disclosed in WO2009/108423, ammonium hydroxide is present in the immediate vicinity ofthe injecting well, and therefore, in the steam chamber in a SAGDprocess, when the oil recovery formulation or the mixture of separatelyinjected ammonia and low quality steam is injected into the formation.The ammonium hydroxide is present in the immediate vicinity of theinjecting well and in the steam chamber because a sufficient quantity ofwater condensate is present to react with the ammonia to form ammoniumhydroxide either in the oil recovery formulation prior to injecting theoil recovery formulation into the formation or immediately upon mixingseparately injected ammonia and low quality steam into the formation.The ammonium hydroxide may react with petroleum acids of the residualoil in the steam chamber to form an oil-emulsifying soap that promotesthe formation of a low viscosity oil-in-water emulsion with the watercondensate of the low quality steam. The oil-in-water emulsion may bemobilized for production from the formation due to its low viscosity andlow interfacial tension.

The process of the present invention is also suited for improving theoil recovery in a cyclic steam stimulation (CSS) process relative to aconventional CSS process. Further, the process of the present inventionis also suited for improving the oil recovery in a vertical steam drive(VSD) process relative to a conventional VSD process.

The oil recovery formulation used in the process of the presentinvention is comprised of ammonia and steam, where the steam used is oflow quality, specifically the steam has a vapor quality of less than0.7. As used herein, “vapor quality” is defined as the fraction of themass of a saturated fluid that is vapor. Vapor quality is definedaccording to the following equation:χ=[m_(vapor)/(M_(vapor)+M_(liquid))], where χ is the vapor quality and mis mass (measured in the same units for each m). Fluids that are notsaturated fluids, such as compressed fluids and superheated fluids, donot have a defined vapor quality. The vapor quality of steam may becalculated from the temperature and pressure of the steam according toconventional methods known to those of ordinary skill in the art. Thesteam of the oil recovery formulation may have a vapor quality of lessthan 0.7, or from greater than 0 to less than 0.7, or from 0.05 to 0.65,or from 0.25 to 0.6.

The ammonia of the oil recovery formulation is preferably gaseousanhydrous ammonia. Alternatively, the ammonia of the oil recoveryformulation may be contained in a gaseous ammonia-steam mixture (priorto being mixed with the low quality steam of the oil recoveryformulation) containing up to 30 wt. % steam, or up to 20 wt. % steam,or up to 10 wt. % steam, or up to 5 wt. % steam. Alternatively, but lesspreferably, the ammonia may be a pressurized anhydrous ammonia liquid,or may be contained in an aqueous ammonia solution containing up to 35%ammonia by mass.

The oil recovery formulation may contain ammonia in an amount effectiveto form sufficient ammonium hydroxide to react with petroleum acids inthe oil to form one or more surfactants in a quantity sufficient tomobilize a portion of the oil in the formation. The oil recoveryformulation may be comprised of from 0.001 wt. % to 90 wt. % ammonia.Preferably the amount of ammonia in the oil recovery formulation is ator near a minimum amount effective to form sufficient ammonium hydroxideto react with petroleum acids in the oil to form one or more surfactantsin a quantity sufficient to mobilize a portion of the oil in theformation, thereby maximizing the amount of steam and thermal energyprovided by the oil recovery formulation to the formation formobilization of the oil. In this embodiment of the process of thepresent invention, the oil recovery formulation may contain from 50parts per million (ppm) to 50,000 ppm by weight of ammonia, or from 100ppm to 10,000 ppm by weight of ammonia.

The oil recovery formulation used in the process of the presentinvention may contain components other than low quality steam andammonia. The oil recovery formulation may contain an anionic surfactantor a non-ionic surfactant that may form an oil-emulsifying soap uponcontacting bitumen or heavy oil in a formation, promoting the formationof a low viscosity oil-in-water emulsion with condensed water from theoil recovery formulation and thereby mobilizing the bitumen or heavy oilfor production from the formation. An anionic surfactant or non-ionicsurfactant utilized in the oil recovery formulation should be stable atthe temperature of the steam utilized in the oil recovery formulation.Anionic surfactants that may be utilized in the oil recovery formulationmay be selected from the group of high temperature stable surfactantsconsisting of an alpha olefin sulfonate compound, an internal olefinsulfonate compound, a branched alkyl benzene sulfonate compound, apropylene oxide sulfate compound, an ethylene oxide sulfate compound, anethylene oxide-propylene oxide sulfate compound, and blends thereof.Amine compounds may be absent from the oil recovery formulation, and theoil recovery formulation may be free of amine compounds. In anembodiment of a process of the present invention, the oil recoveryformulation may consist essentially of ammonia and steam having a vaporquality of less than 0.7.

The oil recovery formulation may be produced by mixing ammonia and a lowquality steam having a vapor quality of less than 0.7, or having a vaporquality of from greater than 0 to less than 0.7, or from 0.05 to 0.65,or from 0.25 to 0.6. The ammonia and the low quality steam may becontacted and mixed to form the oil recovery formulation prior tointroducing the oil recovery formulation to a well for injection into asubterranean formation containing bitumen or heavy oil. Alternatively,the ammonia and low quality steam may be contacted and mixed uponintroduction of the ammonia and the low quality steam to a well forinjection into a subterranean formation containing bitumen or heavy oil,or may be contacted and mixed within the injection well prior toinjection of the oil recovery formulation into the formation.

In another embodiment, the ammonia and low quality steam may be injectedseparately into a subterranean formation containing bitumen and heavyoil and mixed to form the oil recovery formulation in the immediatevicinity of the injection well. In one embodiment of the process of thepresent invention, the injection well may have a conduit extending fromthe wellhead to perforations or openings in the well at a positionlocated in the formation through which the low quality steam may beinjected and a separate conduit extending from the wellhead toperforations or openings in the well at a position located in theformation through which the ammonia may be injected into the formation,where the perforations or openings through which the steam is injectedinto the formation and the perforations or openings through which theammonia is injected into the formation are positioned in the well toensure that the steam and ammonia are mixed together upon injection intothe formation through the well. In one embodiment, perforations oropenings or a set of perforations or openings in the well for injectingthe steam into the formation and perforations or openings or a set ofperforations or openings in the well for injecting ammonia into theformation are positioned to alternate along a portion of the injectingwell within the formation.

In the process of the present invention, the oil recovery formulation,or components thereof, is/are introduced into an oil-bearing formation.The oil-bearing formation comprises oil that may be separated andproduced from the formation after contact and mixing with the oilrecovery formulation. The oil of the oil-bearing formation is a heavyoil or bitumen having a TAN of at least 0.1. “TAN”, as used herein,refers to a total acid number of a bitumen or heavy oil expressed asmilligrams (“mg”) of KOH per gram of the heavy oil or bitumen as may bedetermined by ASTM Method D664.

The oil contained in the oil-bearing formation may have a dynamicviscosity under formation conditions (in particular, at temperatureswithin the temperature range of the formation) of at least 1 mPa s (1cP), or at least 10 mPa s (10 cP), or at least 100 mPa s (100 cP), or atleast 1000 mPa s (1000 cP), or at least 10000 mPa s (10000 cP). The oilcontained in the oil-bearing formation may have a dynamic viscosityunder formation temperature conditions of from 1 to 10000000 mPa s (1 to10000000 cP). Typically, the heavy oil or bitumen in the formation mayhave a dynamic viscosity of at least 100 mPa s (100 cP), or at least 500mPa s (500 cP), or at least 1000 mPa s (1000 cP).

The oil-bearing formation is a subterranean formation. The subterraneanformation may be comprised of one or more porous matrix materialsselected from the group consisting of a porous mineral matrix, a porousrock matrix, and a combination of a porous mineral matrix and a porousrock matrix, where the porous matrix material may be located beneath anoverburden at a depth ranging from 50 meters to 6000 meters, or from 100meters to 4000 meters, or from 200 meters to 2000 meters under theearth's surface. The subterranean formation may be a subsea subterraneanformation.

The porous matrix material may be a consolidated matrix material inwhich at least a majority, and preferably substantially all, of the rockand/or mineral that forms the matrix material is consolidated such thatthe rock and/or mineral forms a mass in which substantially all of therock and/or mineral is immobile when oil, the oil recovery formulation,water, or other fluid is passed therethrough. At least 95 wt. % or atleast 97 wt. %, or at least 99 wt. % of the rock and/or mineral may beimmobile when oil, the oil recovery formulation, water, or other fluidis passed therethrough so that any amount of rock or mineral materialdislodged by the passage of the oil, oil recovery formulation, water, orother fluid is insufficient to render the formation impermeable to theflow of the oil recovery formulation, oil, water, or other fluid throughthe formation. Alternatively, the porous matrix material may be anunconsolidated matrix material in which at least a majority, orsubstantially all, of the rock and/or mineral that forms the matrixmaterial is unconsolidated. The formation may have a permeability offrom 0.0001 to 15 Darcys, or from 0.001 to 1 Darcy. The rock and/ormineral porous matrix material of the formation may be comprised ofsandstone and/or a carbonate selected from dolomite, limestone, andmixtures thereof—where the limestone may be microcrystalline orcrystalline limestone and/or chalk.

Oil in the oil-bearing formation may be located in pores within theporous matrix material of the formation. The oil in the oil-bearingformation may be immobilized in the pores within the porous matrixmaterial of the formation, for example, by capillary forces, byinteraction of the oil with the pore surfaces, by the viscosity of theoil, or by interfacial tension between the oil and water in theformation.

The oil-bearing formation may also be comprised of water, which may belocated in pores within the porous matrix material. The water in theformation may be connate water, water from a secondary or tertiary oilrecovery process water-flood, or a mixture thereof. The water in theoil-bearing formation may be positioned to immobilize petroleum withinthe pores. Contact of the oil recovery formulation with the oil andwater in the formation may mobilize the oil in the formation forproduction and recovery from the formation by freeing at least a portionof the oil from pores within the formation by reducing interfacialtension between water and oil in the formation and by reducing theviscosity of the oil in the formation.

In some embodiments, the oil-bearing formation may compriseunconsolidated sand and water. The oil-bearing formation may be an oilsand formation. Unconsolidiated oil sand material of the oil sandformation may have a tensile strength of about 0 Pa. In someembodiments, the oil may comprise between about 1 wt. % and about 16 wt.% of the oil/sand/water mixture, the sand may comprise between about 80wt. % and about 85 wt. % of the oil/sand/water mixture, and the watermay comprise between about 1 wt. % and about 16 wt. % of the oil/sandwater mixture. The sand may be coated with a layer of water with the oilbeing located in the void space around the wetted sand grains.

Referring now to FIGS. 1 and 2, oil production systems 100 areillustrated that may be used to practice one or more embodiments of aSAGD process in accordance with the process of the present invention. Anoil production system 100 includes an oil-bearing formation 105 that maybe comprised of oil-bearing portions 104, 106, and 108 located beneathan overburden 102. The oil production system 100 may include a firstwell 132 through which the oil recovery formulation, or componentsthereof, may be injected into the formation 105, and a second well 112through which oil, water, and optionally gas, may be produced. The oilproduction system may also include a water storage facility 116, anammonia storage facility 118, an oil recovery formulation storagefacility 130, an oil storage facility 134, and a gas storage facility136.

The oil production system 100 may also include a processing facility110. The processing facility 110 may include a water processing system120 and a separation unit 122. Referring now to FIG. 3, the waterprocessing system 120 may be comprised of a water purification unit 202comprising one or more particulate filters 204, which may include anultrafiltration membrane; one or more ionic filtration units 206 such asa nanofiltration membrane unit and/or a reverse osmosis unit; and/or oneor more ion exchange systems 208 for removing ions from water. Sourcewater may enter the water purification unit 202 through line 212 andproceed through the particulate filters 204 for removal of suspendedsolids from the source water, and then proceed through the ionicfiltration unit 206 and/or the ion exchange system 208 for removal ofions, particularly multivalent cations, from the water. The waterprocessing system may also be comprised of a boiler 210 that is fluidlyoperatively coupled to the water purification unit 202 via line 214 toreceive purified water from the water purification unit. The boiler 210may be configured to produce low quality steam having a vapor quality offrom greater than 0 to less than 0.7, or from 0.05 to 0.65, or from 0.25to 0.6, from the purified water produced by the water purification unit,where the steam may be exported from the water processing system 120 vialine 216.

The separation unit 122 of the processing facility 110 may be designedto separate oil, gas, and an aqueous phase produced from the formation.The separation unit 122 may be comprised of a 2-phase separator 230 anda water knockout vessel 232. The 2-phase separator 230 of the separationunit 122 may be fluidly operatively coupled to the second well byconduit 234 to receive oil, gas, and an aqueous solution produced fromthe formation by the second well. The produced oil and aqueous solutionmay be separated from produced gas in the 2-phase separator 230, wherethe separated produced gas may be exported from the 2-phase separatorand separation unit 122 through conduit 236. The produced oil andaqueous solution may be provided from the 2-phase separator 230 to thewater knockout vessel 232 via conduit 238. The produced oil may beseparated from the aqueous solution in the water knockout vessel, whereseparation aids such as a demulsifier and/or a brine solution may beprovided to the water knockout vessel through inlet 240 to aid in theseparation of the produced oil from the aqueous solution in accordancewith methods known to those skilled in the art of separating oil andaqueous phases from a fluid containing an oil phase and an aqueousphase. The produced oil may be exported from the water knockout vessel232 and the separation unit 122 through conduit 242, and the aqueoussolution may be exported from the water knockout vessel 232 and theseparation unit 122 through conduit 244.

Referring back to FIGS. 1 and 2, the first well 132 and the second well112 extend from the surface 140 into one or more of the oil-bearingportions 104, 106, and 108 of the subterranean oil-bearing formation105. A subsurface portion 142 of the first well 132 and a subsurfaceportion 144 of the second well may traverse one or more oil-bearingportions of the formation 105. The subsurface portion 144 of the second,producing, well 112 may be located below the subsurface portion 142 ofthe first, injecting, well 132. The subsurface portions 142 and 144 ofthe first and second wells 132 and 112, respectively, may be positionedtransverse to portions 146 and 148 of the first and second wells 132 and112, respectively, that extend from the surface 140 to the respectivesubsurface portions 142 and 144 of the wells. The subsurface portion 142of the first well 132 and the subsurface portion 144 of the second well112 may extend horizontally through the formation, and the horizontallyextending subsurface portion 144 of the second well 112 may extendparallel to and below the horizontally extending subsurface portion 142of the first well 132.

The vertical spacing between the horizontal subsurface portion 142 ofthe first well 132 and the horizontal subsurface portion 144 of thesecond well 112 may be from 2 meters to 150 meters, or from 5 meters to100 meters. The horizontal subsurface portion 142 of the first well 132and the horizontal subsurface portion 144 of the second well 112 mayhave a length of from 25 meters to 2000 meters, or from 50 meters to1000 meters, or from 100 meters to 500 meters. The horizontal subsurfaceportion 144 of the second well 112 is preferably as long as, or longerthan, the horizontal subsurface portion 142 of the first well 132.

As shown in FIG. 1, a toe section 150 of the subsurface portion 142 ofthe first well 132 may be aligned with a heel section 152 of thesubsurface portion 144 of the second well. Alternatively, as shown inFIG. 2, a heel section 154 of the subsurface portion 142 of the firstwell 132 may be aligned with the heel section 152 of the subsurfaceportion 144 of the second well 112. Referring again to FIGS. 1 and 2,although the wells 132 and 112 are shown with an abrupt right angletransition from vertical to horizontal, in some embodiments wells 132and 112 may have a smooth transition from vertical to deviated tohorizontal, for example with a smooth curved radius.

Referring now to FIGS. 1, 2, and 3, in a process of the presentinvention the oil recovery formulation comprising ammonia and steamhaving a vapor quality of from greater than 0 to less than 0.7, orcomponents thereof, is/are injected into one or more oil-bearingportions 104, 106, or 108 of the oil-bearing formation 105 comprisingheavy oil or bitumen through the first, injecting, well 132. The oilrecovery formulation may be provided to the first well 132 from an oilrecovery formulation storage facility 130 that is fluidly operativelycoupled to the first well via conduit 129 to provide the oil recoveryformulation to the first well. Steam may be provided to the oil recoveryformulation storage facility 130 by providing source water from thewater storage facility 116 to the water processing unit 120 of theprocessing facility 110 via conduit 212, where particulates and ions areremoved from the source water in the water purification unit 202 andsteam having a vapor quality of from greater than 0 to less than 0.7 isformed in the boiler 210 and provided to the oil recovery formulationstorage facility via conduit 216. Ammonia may be provided to the oilrecovery formulation storage facility 130 from the ammonia storagefacility 118 via conduit 160. Alternatively, steam having a vaporquality of from greater than 0 to less than 0.7 may be provided directlyfrom the boiler 210 to the first well 132 and ammonia may be provideddirectly from the ammonia storage facility to the first well 132 to formthe oil recovery formulation near or within the first well, or to beinjected into the formation as separate components that are mixed in theformation in the immediate vicinity of the first well to form the oilrecovery formulation—in which cases the oil recovery formulation storagefacility 130 may be excluded from the system. The amount of ammoniaincluded in the oil recovery formulation injected into the formation, orinjected into the formation to form the oil recovery formulation, may befrom 0.001 wt. % to 90 wt. % of the oil recovery formulation, or may befrom 50 parts per million (ppm) by weight to 50,000 ppm by weight of theoil recovery formulation.

The oil recovery formulation, or components thereof, may be injectedinto the formation 105 through the subsurface portion 142 of the firstwell 132. The subsurface portion 142 of the first well 132 may haveperforations or openings along the length of the portion 142 throughwhich the oil recovery formulation, or components thereof, may beinjected into the formation.

The oil recovery formulation, or components thereof, may be injectedinto the formation under sufficient pressure to introduce the oilrecovery formulation, or its components, into the formation. The oilrecovery formulation, or its components, may be injected into theformation at a pressure above the initial pressure of the formation atthe injection point, and may be injected at a pressure ranging fromimmediately above the initial pressure of the formation up to thefracture pressure of the formation, or even above the fracture pressureof the formation. In an embodiment of the process of the presentinvention, the oil recovery formulation may be injected into theformation at a pressure of from immediately above the formation pressureto 37,000 kPa above the initial pressure of the formation.

Upon injection of the oil recovery formulation into the formation 105,the oil recovery formulation may contact and mix with oil within theformation. If one or more of the components of the oil recoveryformulation are injected separately, the components of the oil recoveryformulation may be contacted and mixed in the immediate vicinity of thefirst, injecting, well 132 to form the oil recovery formulation, whichthen may contact and mix with oil in the formation. Contacting the oilrecovery formulation with oil in the formation may reduce the viscosityof the oil, for example by heating the oil with the sensible heat andthe latent heat of condensation of the steam in the oil recoveryformulation. Contacting the oil recovery formulation with the oil in theformation may also induce the formation of an oil-in-water emulsionhaving a viscosity of the same magnitude as water by contact with waterpresent in, or condensed from, the low quality steam of the oil recoveryformulation Ammonium hydroxide present in the oil recovery formulationas a result of contact of ammonia and water present in, or condensedfrom, the low quality steam may react with the oil to form an oilemulsifying soap that may enhance the formation of the oil-in-wateremulsion.

The oil in the formation may be mobilized for production by contact withthe oil recovery formulation. The reduction of the oil viscosity byexchange of thermal energy with the steam of the oil recoveryformulation and the formation of the low viscosity oil-in-water emulsionmay mobilize the oil contacted by the oil recovery formulation relativeto oil initially present in the formation. The mobilized reducedviscosity oil and the oil-in-water emulsion may be freed to fall towardthe second, production, well 112, from which the oil and the emulsionmay be produced from the formation.

The process of the present invention may comprise forming a steamchamber 170 in the formation 205; injecting the oil recovery formulationor the components of the oil recovery formulation into the steam chamber170; and recovering residual oil from the steam chamber after injectingthe oil recovery formulation or the components of the oil recoveryformulation into the steam chamber. The steam chamber 170 may be formedby injecting steam into the formation through the first well 132 and thesecond well 112 for a first period of time. The steam injected in thisfirst period of time is preferably high quality dry steam having a vaporquality of at least 0.9. The steam injected in the first period of timereduces the viscosity of oil in the immediate vicinity of the first well132 and the second well 112. Steam injection may be stopped from thesecond well 132 after the first period of time, and reduced viscosityoil may be produced from the second well 132. Steam may be injectedagain through the second well to reduce the viscosity of more oil in theformation, and then the additional reduced viscosity oil may berecovered from the second well. Steam injection through the first andsecond wells 132 and 112, and production of oil from the second well 112may be continued in this manner until a steam chamber 170 is formed inthe formation. The steam chamber has a reduced quantity of oil therein(the “residual oil”) relative to the amount of oil present in theformation at the boundary of the steam chamber and portions of theformation outside of the steam chamber.

The oil recovery formulation, or components thereof, may be injectedinto the steam chamber 170 through the subsurface portion 142 of thefirst well 132. The oil recovery formulation may contact the residualoil in the steam chamber 170 and mobilize the residual oil as describedabove relative to oil in the formation. The oil recovery formulation issuited to mobilize the residual oil in the steam chamber since the steamis low vapor quality steam containing a substantial amount of condensedwater containing ammonium hydroxide that forms oil emulsifying soapsupon contacting the residual oil, where the condensed water may thenform an oil-in-water emulsion that is mobilized for production from theformation. The mobilized residual oil may fall from the steam chamber170 to the second well 112 for production from the formation.

A portion of the oil recovery formulation may pass through the steamchamber 170 to the interface of the steam chamber with portions of theformation outside of the steam chamber. This portion of the oil recoveryformulation may mobilize oil at the interface of the steam chamber andthe portions of the formation outside the steam chamber for productionfrom the formation as described above. The mobilized “interface” oil mayfall from the interface to the second well 112 for production from theformation.

The mobilized oil, water, and optionally gas, may be produced from theformation through the second well 112 by conventional oil productionprocesses. The well 112 may include conventional mechanisms forproducing oil from a formation, including lift pumps, lift gases, and/ora compressor for injecting gas into the formation to produce the oil,water, and optionally gas from the formation.

Referring now to FIGS. 1, 2, and 3, the oil, water, and gas producedfrom the formation through the second well may be processed andseparated. The second well 112 may be fluidly operatively coupled to the2-phase separator 230 of the separation unit 122 via conduit 234. Asdescribed above, the produced oil, produced gas, and an aqueous solutionmay be separated in the separation unit 122. The separated produced oilmay be provided from the water knockout vessel 232 of the separationunit to the oil storage facility 134 via conduit 242. The separatedproduced gas may be provided from the 2-phase separator 230 of theseparation unit 122 to the gas storage facility 136 via conduit 236. Theseparated aqueous solution may be provided from the water knockoutvessel 232 to the water storage facility 116 via conduit 244.

The process of the present invention may also be utilized in a cyclicsteam stimulation (“CSS”) oil recovery process. Referring now to FIGS. 4and 5, an oil production system utilizing a single well for injectionand production according to a CSS process in accordance with the processof the present invention is shown. The system 300 may be similar in somerespects to the system 100 described above with reference to FIGS. 1 and2 and with the water processing system of FIG. 2. Accordingly, thesystem 300 may be understood with reference to FIGS. 1, 2, and 3, wherelike numerals are used to indicate like components that will not bedescribed again in detail.

As shown in FIG. 4, an oil recovery formulation comprised of ammonia andlow quality steam, or components thereof, may be injected into aformation 105 through well 312. The oil recovery formulation may beprovided to the well 312 from an oil recovery formulation storagefacility 130 via conduit 302, where ammonia may be provided to the oilrecovery formulation storage facility 130 from an ammonia storagefacility 118 via conduit 160, and steam may be provided to the oilrecovery formulation storage facility via conduit 216 from a waterprocessing system 120 including a water purification system and a boilerfor producing steam having a vapor quality of from greater than 0 toless than 0.7 from water provided from a water storage facility 116 viaconduit 212. Alternatively, the components of the oil recoveryformulation may be provided separately to the well 312 from the ammoniastorage facility 118 and the water processing system 120 of theprocessing facility 110 for mixing at the well, within the well, or uponinjection into the formation, as described above.

The oil recovery formulation, or components thereof, may be injectedinto the formation 105 through the well 312 to contact and mix withheavy oil or bitumen in the formation, as shown by arrows 314. The oilrecovery formulation may reduce the viscosity of the heavy oil orbitumen upon contact by heating the heavy oil or bitumen, as describedabove, and thereby mobilize the oil for recovery from the formation. Theoil recovery formulation may also induce the formation of anoil-in-water emulsion by the formation of oil-emulsifying soaps producedby reaction of ammonium hydroxide with petroleum acids in the oil orbitumen and thereby form and mobilize an oil-in-water emulsion forproduction from the formation.

The oil recovery formulation, or components thereof, may be injectedinto the formation through the well 312 for a first period of time afterwhich injection of the oil recovery formulation, or components thereof,may be ceased. The oil recovery formulation may be allowed to soak inthe formation after cessation of injection of the oil recoveryformulation, or the components thereof.

Then, as shown in FIG. 5, the mobilized oil, water, and optionally gas,may be produced from the formation through the well 312. The mobilizedoil, water, and optionally gas, may be drawn through the formation asshown by arrows 316 for production from the well. The well 312 mayinclude conventional mechanisms for producing oil from a formation,including lift pumps, lift gases, and/or a compressor for injecting gasinto the formation to produce the oil, water, and optionally gas fromthe formation.

The oil, water, enhanced oil recovery formulation, and gas produced fromthe well 312 may be separated in the processing facility 110 and storedas described above.

In one embodiment of a CSS process in accordance with the process of thepresent invention, prior to injecting the oil recovery formulation intothe formation and subsequently recovering mobilized oil, water, andoptionally gas therefrom, high quality steam having a vapor quality ofat least 0.7, or at least 0.9, may be injected into the formation 105through well 312 to contact and mix and soak with heavy oil or bitumenin the formation to mobilize the heavy oil or bitumen, and then themobilized oil may be recovered through well 312. The cycle of injectionof high quality steam into the formation; contacting, mixing, andsoaking the high quality steam with the bitumen or heavy oil to mobilizethe oil, and recovery of the mobilized oil from the well may be effectedone or two or more times prior to injecting the oil recovery formulationinto the formation; contacting, mixing, and soaking the oil recoveryformulation with bitumen or heavy oil in the formation to mobilize theoil in the formation; and recovering the mobilized oil from the wellthrough which the oil recovery formulation was injected into theformation. Use of the oil recovery formulation as described above afterCSS oil recovery using high quality steam enables recovery of residualoil in the formation.

The process of the present invention may also be utilized in a verticalsteam drive (“VSD”) oil recovery process. Referring now to FIG. 6, anoil production system 400 is illustrated that may be used to practiceone or more embodiments of a vertical steam drive (VSD) process inaccordance with the process of the present invention. The system may besimilar in some respects to the system 100 described above with respectto FIGS. 1 and 2 and the water processing system as shown in FIG. 3.Accordingly, the system 400 may be understood with reference to FIGS. 1,2, and 3, where like numerals are used to indicate like components thatwill not be described again in detail.

As shown in FIG. 6, an oil recovery formulation comprised of ammonia andlow quality steam, or components thereof, may be injected into aformation 105 through a first well 432. The oil recovery formulation maybe provided to the first well 432 from an oil recovery formulationstorage facility 130 via conduit 129, where ammonia may be provided tothe oil recovery formulation storage facility 130 from an ammoniastorage facility 118 via conduit 160, and steam may be provided to theoil recovery formulation storage facility via conduit 216 from a waterprocessing system 120 including a water purification system and a boilerfor producing steam having a vapor quality of from greater than 0 toless than 0.7 from water provided from a water storage facility 116 viaconduit 212. Alternatively, the components of the oil recoveryformulation may be provided separately to the first well 432 from theammonia storage facility 118 and the water processing system 120 formixing at the first well, within the first well, or upon injection intothe formation 105, as described above.

The oil recovery formulation, or components thereof, may be injectedinto the formation 105 through the first well 432 to contact and mixwith heavy oil or bitumen, as described above, and thereby mobilize theoil for recovery from the formation. The oil recovery formulation mayreduce the viscosity of the heavy oil or bitumen upon contact by heatingthe heavy oil or bitumen, as described above, and thereby mobilize theoil for recovery from the formation 105. The oil recovery formulationmay also induce the formation of an oil-in-water emulsion by theformation of oil-emulsifying soaps produced by reaction of ammoniumhydroxide with petroleum acids in the oil or bitumen and thereby formand mobilize an oil-in-water emulsion for production from the formation.

The mobilized oil may be pushed across the formation 105 from the firstwell 432 to the second well 412 as shown by arrows 414 and 416 byfurther introduction of more oil recovery formulation into the formationor by introduction of an oil immiscible drive fluid into the formationsubsequent to injection of the oil recovery formulation into theformation.

The oil immiscible drive fluid may be introduced into the formation 105through the first well 432 to force or otherwise displace the mobilizedoil toward the second well 412 for production. The oil immiscible drivefluid may be configured to displace the mobilized oil through theformation 105. Suitable oil immiscible drive fluids are not firstcontact miscible or multiple contact miscible with oil in the formation105. The oil immiscible drive fluid may be selected from the groupconsisting of an aqueous polymer fluid, water, carbon dioxide at apressure below its minimum miscibility pressure, nitrogen at a pressurebelow its minimum miscibility pressure, air, and mixtures of two or moreof the preceding.

Suitable polymers for use in an aqueous polymer fluid may include, butare not limited to, polyacrylamides, partially hydrolyzedpolyacrylamides, polyacrylates, ethylenic copolymers, biopolymers,carboxymethylcellulose, polyvinyl alcohols, polystyrene sulfonates,polyvinylpyrolidones, AMPS (2-acrylamide-2-methyl propane sulfonate),combinations thereof, or the like. Examples of ethylenic copolymersinclude copolymers of acrylic acid and acrylamide, acrylic acid andlauryl acrylate, lauryl acrylate and acrylamide. Examples of biopolymersinclude xanthan gum, guar gum, alginates, and alginic acids and theirsalts. In some embodiments, polymers may be crosslinked in situ in theformation 105. In other embodiments, polymers may be generated in situin the formation 105.

The oil immiscible drive fluid may be stored in, and provided forintroduction into the formation 105 from, an oil immiscible drive fluidstorage facility 420 that may be fluidly operatively coupled to thefirst well 432 via conduit 422. The amount of oil immiscible drive fluidintroduced into the formation 105 should be sufficient to drive themobilized oil across at least a portion of the formation.

If the oil immiscible drive fluid is in liquid phase, the oil immiscibledrive fluid may have a viscosity of at least the same magnitude as theviscosity of the mobilized oil at formation temperature conditions toenable the oil immiscible drive fluid to drive the mobilized oil acrossthe formation 105 to the second well 412. The oil immiscible formulationmay have a viscosity of at least 0.8 mPa s (0.8 cP) or at least 10 mPa s(10 cP), or at least 50 mPa s (50 cP), or at least 100 mPa s (100 cP),or at least 500 mPa s (500 cP), or at least 1000 mPa s (1000 cP), or atleast 10000 mPa s (10000 cP) at formation temperature conditions or at25° C. If the oil immiscible drive fluid is in liquid phase, preferablythe oil immiscible drive fluid may have a viscosity at least one orderof magnitude greater than the viscosity of the mobilized oil atformation temperature conditions so the oil immiscible drive fluid maydrive the mobilized oil across the formation in plug flow, minimizingand inhibiting fingering of the mobilized oil through the driving plugof oil immiscible formulation.

The oil recovery formulation and the oil immiscible drive fluid may beintroduced into the formation 105 through the first well 432 inalternating slugs. For example, the oil recovery formulation may beintroduced into the formation 105 through the first well 432 for a firsttime period, after which the oil immiscible drive fluid may beintroduced into the formation through the first well for a second timeperiod subsequent to the first time period, after which the oil recoveryformulation may be introduced into the formation through the first wellfor a third time period subsequent to the second time period, afterwhich the oil immiscible drive fluid may be introduced into theformation through the first well for a fourth time period subsequent tothe third time period. As many alternating slugs of the oil recoveryformulation and the oil immiscible drive fluid may be introduced intothe formation through the first well as desired.

Oil may be mobilized for production from the formation 105 via thesecond well 412 by introduction of the oil recovery formulation and,optionally, the oil immiscible drive fluid into the formation, where themobilized oil is driven through the formation for production from thesecond well as indicated by arrows 416 by introduction of the oilrecovery formulation and optionally the oil immiscible drive fluid intothe formation via the first well 432.

The mobilized oil, water and optionally gas may be produced from theformation 105 through the second well 412 by conventional oil productionprocesses. The well 412 may include conventional mechanisms forproducing oil from a formation, including lift pumps, lift gases, and/ora compressor for injecting gas into the formation to produce the oil,water, and optionally gas from the formation. Oil, water and gasproduced from the formation may be processed, separated, and stored asdescribed above.

In an embodiment of a VSD process in accordance with the process of thepresent invention, the first well 432 may be used for introducing theoil recovery formulation and, optionally, subsequently the oilimmiscible drive fluid into the formation 105 and the second well 412may be used for producing oil, water, and optionally gas from theformation for a first time period; then the second well 412 may be usedfor introducing the oil recovery formulation and, optionally,subsequently the oil immiscible drive fluid into the formation 105 andthe first well 432 may be used for producing oil, water, and optionallygas from the formation for a second time period; where the first andsecond time periods comprise a cycle. Multiple cycles may be conductedwhich include alternating the first well 432 and the second well 412between introducing the oil recovery formulation and, optionally,subsequently the oil immiscible drive fluid into the formation 105, andproducing oil, water, and optionally gas from the formation, where onewell is introducing and the other is producing for the first timeperiod, and then they are switched for a second time period. A cycle maybe from about 12 hours to about 1 year, or from about 3 days to about 6months, or from about 5 days to about 3 months. The oil recoveryformulation may be introduced into the formation at the beginning of acycle and the oil immiscible drive fluid may be introduced at the end ofthe cycle. In some embodiments, the beginning of a cycle may be thefirst 10% to about 80% of a cycle, or the first 20% to about 60% of acycle, the first 25% to about 40% of a cycle, and the end may be theremainder of the cycle.

In one embodiment of a VSD process in accordance with the process of thepresent invention, high quality steam is injected through the first well432 and oil is produced from the second well 412, or one or more cyclesof alternately injecting high quality steam and producing oil from thefirst and second wells, respectively, is effected prior to injecting theoil recovery formulation into the formation and subsequently recoveringmobilized oil therefrom. The high quality steam has a vapor quality ofat least 0.7, and may have a vapor quality of at least 0.9, or at least0.95, or at least 0.97. The high quality steam may be provided by thewater processing system 120, where the operating conditions of theboiler 210 may be adjusted to produce the high quality steam. The highquality steam may be injected into the formation 105 through the firstwell 432 to contact and mix with heavy oil or bitumen in the formationto mobilize the heavy oil or bitumen, and then the mobilized oil may berecovered through the second well 412. An oil immiscible drive fluid asdescribed above may by injected into the formation subsequent toinjection of the high quality steam to drive mobilized oil across theformation 105 for production through the second well 412. Alternatingslugs of the high quality steam and the oil immiscible drive fluid maybe injected into the formation through the first well 412 whileproducing oil through the second well 432 prior to injection of the oilrecovery formulation into the formation and attendant recovery of oilfrom the formation. Optionally, cycles of alternating slugs of highquality steam and an oil immiscible drive fluid may be injected into theformation via the first and second wells while producing oil through thesecond and first wells, respectively, prior to injection of the oilrecovery formulation into the formation and attendant recovery of oilfrom the formation. Injection of the oil recovery formulation into theformation subsequent to injection of high quality steam and attendantproduction of mobilized oil from the formation may promote the recoveryof residual oil from the formation, where the residual oil is oil leftin the formation and not mobilized or recovered by the injection of thehigh quality steam into the formation and production of oil mobilized bythe high quality steam.

The present invention is well adapted to attain the ends and advantagesmentioned as well as those that are inherent therein. The particularembodiments disclosed above are illustrative only, as the presentinvention may be modified and practiced in different but equivalentmanners apparent to those skilled in the art having the benefit of theteachings herein. Furthermore, no limitations are intended to thedetails of construction or design herein shown, other than as describedin the claims below. It is therefore evident that the particularillustrative embodiments disclosed above may be altered, combined, ormodified and all such variations are considered within the scope of thepresent invention. The invention illustratively disclosed hereinsuitably may be practiced in the absence of any element that is notspecifically disclosed herein and/or any optional element disclosedherein. While compositions and methods are described in terms of“comprising,” “containing,” or “including” various components or steps,the compositions and methods can also “consist essentially of” or“consist of” the various components and steps. All numbers and rangesdisclosed above may vary by some amount. Whenever a numerical range witha lower limit and an upper limit is disclosed, any number and anyincluded range falling within the range is specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues. Also, the terms in the claims have their plain, ordinary meaningunless otherwise explicitly and clearly defined by the patentee.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the element that itintroduces. If there is any conflict in the usages of a word or term inthis specification and one or more patent or other documents that may beincorporated herein by reference, the definitions that are consistentwith this specification should be adopted.

What is claimed is:
 1. A process for producing oil, comprising:injecting an oil recovery formulation comprising ammonia and steam intoan underground oil-bearing formation comprising an oil or bitumen havinga total acid number of at least 0.1, wherein the steam has a vaporquality of from greater than 0 to less than 0.7; and producing oil orbitumen from the formation after injection of the oil recoveryformulation into the formation.
 2. The process of claim 1 wherein thesteam of the oil recovery formulation has a vapor quality of from 0.05to 0.65.
 3. The process of claim 1 wherein the oil recovery formulationis free of amines and the oil recovery formulation is injected into theformation in the absence of amines.
 4. The process of claim 1 furthercomprising: forming a steam chamber in the oil-bearing formation; andinjecting the oil recovery formulation into the steam chamber in theformation.
 5. The process of claim 4 further comprising recoveringresidual oil from the steam chamber after injecting the oil recoveryformulation into the formation.
 6. The process of claim 5 wherein theoil recovery formulation is injected into the steam chamber via a welland the residual oil is recovered from the steam chamber via the well.7. The process of claim 1 wherein: the oil recovery formulation isinjected into the formation via a first well, where at least a portionof the first well traverses a portion of the formation; and the oil orbitumen is produced from the formation via a second well, wherein thesecond well traverses a portion of the formation.
 8. The process ofclaim 7 further comprising: forming a steam chamber in the formation;and injecting the oil recovery formulation into the steam chamber in theformation via the first well.
 9. The process of claim 7 wherein asubsurface portion of the second well is positioned below a subsurfaceportion of the first well in the formation.
 10. The process of claim 9wherein the subsurface portion of the second well positioned below thesubsurface portion of the first well in the formation is positionedtransverse to a portion of the second well extending from the surface tothe subsurface portion of the second well, and the subsurface portion ofthe first well is positioned transverse to a portion of the first wellextending from the surface to the subsurface portion of the first well.11. The process of claim 10 wherein the subsurface portion of the firstwell and the subsurface portion of the second well extend horizontallythrough the formation and the subsurface portion of the second wellextends substantially parallel to the subsurface portion of the firstwell.
 12. The process of claim 1 wherein the oil recovery formulationcomprises ammonium hydroxide.
 13. The process of claim 1 furthercomprising the step of mixing ammonia and steam to form the oil recoveryformulation prior to injecting the oil recovery formulation into theformation, wherein the steam mixed with the ammonia has a vapor qualityof from greater than 0 to less than 0.7.
 14. The process of claim 1further comprising injecting steam having a vapor quality of at least0.7 into the formation and subsequently producing oil from the formationprior to injecting the oil recovery formulation into the formation. 15.The process of claim 14 wherein the steam has a vapor quality of atleast 0.95.
 16. A process for producing oil, comprising: injecting steamhaving a vapor quality of from greater than 0 to less than 0.7 into anoil-bearing formation comprising an oil or bitumen having a total acidnumber of at least 0.1; injecting ammonia into the oil-bearing formationto contact the steam within the formation and form an oil recoveryformulation comprising ammonia and steam, wherein the steam has a vaporquality of from greater than 0 to less than 0.7; contacting the oilrecovery formulation with oil in the formation; and producing oil fromthe formation after contacting the oil with the oil recoveryformulation.